There has been conventionally known a combined power generation plant of a so-called multi-axis type combined cycle, comprising: a plurality of gas turbine generator sets each including a gas turbine and a heat recovery steam generator; a plurality of steam turbine generator sets; and an additional set represented as a fresh water generator (see, e.g., JP61-49111A).
A structure of such a power generation plant is described with reference to FIG. 1.
As shown in FIG. 1, the power generation plant comprises a plurality of gas turbine generator sets 101a to 101m each including a gas turbine and a heat recovery steam generator; a plurality of steam turbine generator sets 201a to 201n configured to generate a power with the use of steams sent from the gas turbine generator sets 101a to 101m, a plurality of additional sets 401a to 401p; a plurality of condenser sets 501a to 501q; and a plant control device 800 configured to control the respective aforementioned sets.
In FIG. 1, although only the first sets (the sets shown by the reference numbers having a suffix “a”) of the respective sets are shown, the other sets have the same structure as that of the first set. In addition, as shown in FIG. 1, a combined generator set 100 is composed of the plurality of gas turbine generator sets 101a to 101m and the plurality of steam turbine generator sets 201a to 201n. 
In FIG. 1, a steam generated by the combined generator set 100 is normally sent to the additional sets 401a to 401p. In the additional sets 401a to 401p, the steam becomes a condensed water by a heat exchange, and the condensed water is returned to the gas turbine generator sets 101a to 101m of the generator set 100. When an amount of a steam generated in the combined generator set 100 is larger than an amount of a steam to be used in the additional sets 401a to 401p, the excessive steam is sent to the condenser sets 501a to 501q. 
As shown in FIG. 1, the above-described gas turbine generator set 101a includes: a combustor 103a to which a fuel is sent from outside via a fuel valve 104a, the combustor 103a being configured to burn the fuel so as to generate a combustion gas; a gas turbine 102a to which the combustion gas is sent from the combustor 103a, the gas turbine 102a being configured to be driven by the combustion gas; a gas turbine generator 105a coaxially connected to the gas turbine 102a, the gas turbine generator 105a being configured to perform a primary power generation; and a gas-turbine load detecting unit 106a configured to detect a load of the gas turbine generator 105a. In addition, connected to the gas turbine 102a is a heat recovery steam generator 111a to which a combustion gas is sent from the gas turbine 102a. 
The heat recovery steam generator 111a is adapted to heat a condensed water sent from the below-described additional sets 401a to 401p or the condenser sets 501a to 501q, by using a combustion gas sent from the gas turbine 102a, so as to generate a steam. As shown in FIG. 1, the heat recovery steam generator 111a includes: evaporators 113a and 117a configured to evaporate a steam with the use of a combustion gas from the gas turbine 102a; a deaerator 112a configured to deaerate a condensed water with the use of a steam sent from the evaporator 113a; and a water supply pump 114a configured to increase a pressure of the condensed water deaerated by the deaerator 112a. In addition, the heat recovery steam generator 111a includes: an economizer 115a configured to increase a temperature of the condensed water sent from the water supply pump 114a, with the use of the combustion gas from the gas turbine 102a; a steam drum 116a configured to evaporate the condensed water whose temperature has been increased by the economizer 115a, with the use of the steam sent from the evaporator 117a; and a superheater 118a configured to superheat the steam sent from the steam drum 116a, with the use of the combustion gas from the gas turbine 102a. 
In addition, an auxiliary fuel is supplied from outside to the heat recovery steam generator 111a via an auxiliary fuel valve 120a. The heat recovery steam generator 111a has a duct burner 119a that burns the auxiliary fuel so as to generate an auxiliary combustion gas. The auxiliary combustion gas generated by the duct burner 119a is sent to the evaporators 113a and 117a, the economizer 115, and the superheater 118a. 
A heat-recovery-steam-generator exhaust pressure detecting unit 121a configured to detect a pressure of the steam sent from the superheater 118a, and a flow rate detecting unit 122a configured to detect a flow rate of the steam are connected to the downstream side of the superheater 118a in this order. In addition, there is provided a bypass line 124a through which a steam is directly sent from the heat recovery steam generator 111a to the additional sets 401a to 401p or the condenser sets 501a to 501q, bypassing the steam turbine generator sets 201a to 201n. The bypass line 124a is equipped with a turbine bypass valve 123a. 
The steams sent from the above gas turbine generator sets 101a to 101m are once merged together. A pressure detecting unit 301 configured to detect a pressure of the merged steam is disposed on an upstream side of the steam turbine generator set. The merged steam is diverged again, and the diverged steams are sent to the respective steam turbine generator sets 201a to 201n. 
As shown in FIG. 1, the steam turbine generator set 201a includes: a steam turbine 202a to which a steam is sent from the gas turbine generator sets 101a to 101m via a steam regulating valve 203a configured to regulate a flow rate of the steam, the steam turbine 202a being configured to be driven by the steam; a steam turbine generator 204a coaxially connected to the steam turbine 202a, the steam turbine generator 204a being configured to generate a power; and a steam-turbine load detecting unit 205a configured to detect a load of the steam turbine generator 204a. Disposed on the downstream side of the steam turbine 202a is a steam-turbine exhaust pressure detecting unit 206a configured to detect a pressure of the steam sent from the steam turbine 202a. 
The steams sent form the steam turbine generator sets 201a to 201n and the steams sent from the gas turbine generator sets 101a to 101m through the bypass line 124a are once merged together. A pressure detecting unit 302 configured to detect a pressure of the merged steam is disposed on the downstream side of the steam turbine generator sets. The merged steam is diverged again, and the diverged steams are sent to the respective additional sets 401a to 401p and the condenser sets 501a to 501q. 
The additional set 401 includes: a flow rate detecting unit 404a configured to detect a flow rate of the steam sent thereto in a diverged manner; a heat exchanger 402a disposed on the downstream side of the flow rate detecting unit 404a, the heat exchanger 402a being configured to evaporate a sea water by a heat of the supplied steam so as to generate a fresh water (product water) and configured to convert the steam into a condensed water; and a condensing pump 403a configured to send the condensed water sent from the heat exchanger 402a to the heat recovery steam generators 111a to 111m of the gas turbine generator sets 101a to 101m. A sea water supply system 411 is connected to an inlet side of the heat exchanger 402a, and a sea water returning system 412 and a product water system 413 are connected to an outlet side of the heat exchanger 402a. The aforementioned product water is adapted to be sent to the product water system 413, and an excessive sea water of the sea water sent from the sea water supply system 411 is adapted to be sent to the sea water returning system 412.
The condenser set 501a includes: a flow rate detecting unit 505a configured to detect a flow rate of the steam sent thereto in a diverged manner; a condenser 502a disposed on the downstream side of the flow rate detecting unit 505a, the condenser 502a being configured to cool, by a heat exchange, the steam sent thereto via an adjusting valve 503a for adjusting a flow rate of a steam, so as to generate a condensed water; and a condensing pump 504a configured to send the condensed water sent from the condenser 502a to the heat recovery steam generators 111a to 111m of the gas turbine generator sets 101a to 101m. The sea water supply system 411 is connected to an inlet side of the condenser 502a, and the sea water returning system 412 is connected to an outlet side of the condenser 502a. The condenser 502a is configured to, when a steam is cooled by a sea water, send the sea water heated by the steam to the sea water returning system 412.
There has been described, with reference to FIG. 1, the power generation plant including the condenser sets 501a to 501q. However, instead of providing the condenser sets 501a to 501q, steam dischargeable valves may be provided on the inlet sides and/or the outlet sides of the steam turbine generator sets 101a to 101m, so as to release an excessive steam to the atmosphere.
The structures of the gas turbine generator set 101a, the steam turbine generator set 201a, the additional set 401a, and the condenser set 501a have been described hereabove. Similarly, the gas turbine generator sets 101b to 101m, the steam turbine generator sets 201b to 201n, the additional sets 401b to 401p, and the condenser sets 501b to 501q have the same structures as described above. The number of gas turbine generator sets, the steam turbine generator sets, the additional sets, and the condenser sets to be installed in the power generation plant can be determined depending on a scale of the power generation plant.
Next, an operation of the power generation plant as structured above is described with reference to FIG. 1.
Firstly, in the gas turbine generator set 101a, a fuel is supplied to the combustor 103a via the fuel valve 104a from an outside fuel system. The fuel is burned by the combustor 103a, so that a combustion gas is generated. A flow rate of the fuel to be sent to the gas turbine 102a at this time is adjusted by a valve opening degree of the fuel valve 104a. The combustion gas is sent to the gas turbine 102a, so that the gas turbine 102a is driven by the combustion gas. Thus, the gas turbine generator 105a coaxially connected to the gas turbine 102a generates a power. At this time, a load of the gas turbine generator 105a is detected by the gas-turbine load detecting unit 106a. 
When an amount of a steam required by the heat recovery steam generator 111a is larger than an amount of a steam generated by the combustion gas from the gas turbine 102a, an auxiliary fuel is supplied to the duct burner 119a via the auxiliary fuel valve 120a from outside, in order to compensate the deficit. The auxiliary fuel is burned by the duct burner 119a so as to generate an auxiliary combustion gas, whereby an energy input to the heat recovery steam generator 111a is increased. A flow rate of the auxiliary fuel to be sent to the duct burner 119a is adjusted by a valve opening degree of the auxiliary fuel valve 120a. The combustion gas discharged from the gas turbine 102a and the auxiliary fuel gas discharged from the duct burner 119a are sent to the evaporators 113a and 117a, the economizer 115a, and the superheater 118a of the heat recovery steam generator 111a. The evaporates 113a and 117a generate a steam with the use of the combustion gas sent thereto.
On the other hand, a condensed water is sent from the additional sets 401a to 401p and the condenser sets 501a to 501q to the deaerator 112a of the heat recovery steam generator 111a. In the deaerator 112a, the condensed water is deaerated by a steam sent from the evaporator 113a. A pressure of the deaerated condensed water is increased by the water supply pump 114a, and the deaerated condensed water is sent to the economizer 115a. In the economizer 115a, a temperature of the condensed water is increased by the combustion gas and the auxiliary combustion gas. In addition, the condensed water whose temperature has been increased is sent to the team drum 116a. In the steam drum 116a, the condensed water is evaporated by a steam sent from the evaporator 117a, so as to generate a steam. The steam generated by the steam drum 116a is sent to the superheater 118a. In the superheater 118a, the steam is superheated by the combustion gas and the auxiliary combustion gas.
A pressure of the steam discharged from the heat recovery steam generator 111a is detected by the heat-recovery-steam-generator exhaust pressure detecting unit 121a, and a flow rate thereof is detected by the flow rate detecting unit 122a. Thereafter, when the turbine bypass valve 123a is opened, a part of the steam is diverged therefrom and sent to the bypass line 124a. Thus, the part of the steam is directly sent to the additional sets 401a to 401p or the condenser sets 501a to 501q, without passing through the steam turbine generator sets 201a to 201n. 
On the other hand, as shown in FIG. 1, the steams sent from the respective gas turbine generator sets 101a to 101m are once merged together by, e.g., a steam header, and a pressure of the merged steam is detected by the pressure detecting unit 301 on the upstream side of the steam turbine generator set. The merged steam is diverged again, and the diverged steams are sent to the respective steam turbine generator sets 201a to 201n. 
A flow rate of the steam to be sent to the steam turbine generator set 201a is adjusted by the regulating valve 203a, and the steam is sent to the steam turbine 202a. The steam turbine 202a is driven by the steam sent thereto, so that the steam turbine generator 204 coaxially connected to the steam turbine 202a performs a secondary power generation. At this time, a load of the steam turbine generator 204a is detected by the steam-turbine load detecting unit 205a. Then, a steam is discharged from the steam turbine 202a, and a pressure of the steam is detected by the steam-turbine exhaust pressure detecting unit 206a. 
The steams sent from the steam turbine generator sets 201a to 201n and the steams sent from the gas turbine generator sets 101a to 101m through the bypass line 124a are once merged together by, e.g., a steam header, and a pressure of the merged steam is detected by the pressure detecting unit 302 on the downstream side of the steam turbine generator set. The merged steam is diverged again, and the diverged steams are sent to the respective additional sets 401a to 401p and the condenser sets 501a to 501q. 
In the additional set 401a, a flow rate of the above steam sent thereto in a diverged manner is detected by the flow rate detecting unit 404a, and then the steam is sent to the heat exchanger 402a. On the other hand, a sea water is sent to the heat exchanger 402a from the sea water supply system 411. In the heat exchanger 402a, heats of the steam and the sea water are exchanged, so that the steam is cooled so as to generate a condensed water, and that the sea water is heated to be evaporated so as to generate a product water. The condensed water generated by the heat exchanger 402a is discharged from the additional set 401a by the condensing pump 403a. On the other hand, the product water generated by the heat exchanger 402a is sent to the product water system 413, and is discharged outside the power generation plant. The sea water, which is not converted to a product water and is left in the heat exchanger 402a, is sent to the sea water returning system 412, and is discharged outside the power generation plant.
In the condenser set 501a, a flow rate of the above steam sent thereto in a diverged manner is detected by the flow rate detecting unit 505a. After the flow rate thereof has been adjusted by the adjusting valve 503a, the steam is sent to the condenser 502a. On the other hand, a sea water is sent to the condenser 502a from the sea water supply system 411. In the condenser 502a, heats of the steam and the sea water are exchanged, so that the steam is cooled so as to generate a condensed water, and that the sea water is heated. The condensed water generated by the condenser 502a is discharged from the condenser set 501a by the condensing pump 504a. On the other hand, the sea water heated by the condenser 502a is sent to the sea water returning system 412, and is discharged outside the power generation plant.
The condensed waters discharged from the additional sets 401a to 401p and the condensed waters discharged from the condenser sets 501a to 501q are once merged together. The merged condensed water is diverged again, and the diverged condensed waters are sent to the respective deaerators 112a to 112m of the heat recovery steam generators 111a to 111m of the gas turbine generator sets 101a to 101m. 
Next, there is described the conventional plant control device 800 that controls the gas turbine generator sets 101a to 101m, the steam turbine generator sets 201a to 201n, the additional sets 401a to 401p, and the condenser sets 501a to 501q, with reference to FIGS. 13 to 17.
FIG. 13 is a block diagram showing a control of the fuel valves 104a to 104m disposed on fuel systems of the gas turbines 102a to 102m of the gas turbine generator sets 101a to 101m. FIG. 14 is a block diagram showing a control of the steam regulating valve 203a disposed on a main steam system of the steam turbine 202a of the steam turbine generator set 201a. FIG. 15 is a block diagram showing a control of the auxiliary fuel valves 120a to 120m disposed on fuel systems of the duct burners 119a to 119m of the gas turbine generator sets 101a to 101m. FIG. 16 is a block diagram showing a control of the turbine bypass valve 123a on the bypass line 124a connected to the gas turbine generator set 101a. FIG. 17 is a block diagram showing a control of the adjusting valves 503a to 503q disposed on the upstream sides of the condensers 502a to 502q of the condenser sets 501a to 501q. 
[Control of Fuel Valves of Gas Turbine Generator Sets]
With reference to FIG. 13, there is described the control of the fuel valves 104a to 104m disposed on the upstream sides of the fuel systems of the gas turbines 102a to 102m of the gas turbine generator sets 101a to 101m. 
Firstly, loads of the gas turbine generators 105a to 105m, which are respectively detected by the gas-turbine load detecting units 106a to 106m, are sent to an adder 1. In the adder 1, a sum value of the loads is calculated. Similarly, loads of the steam turbine generators 204a to 204n, which are respectively detected by the steam-turbine load detecting units 205a to 205n, are sent to an adder 2. In the adder 2, a sum value of the loads is calculated. Then, in an adder 3, the sum value of the loads calculated by the adder 1 and the sum value of the loads calculated by the adder 2 are added, and the added value is sent to a subtracter 5.
On the other hand, set in a setting device 4 is a whole generator set load command value, which is sent from a central feed command part, or a whole generator set load command value, which is inputted by an operator. The whole generator set load command value is sent to the subtracter 5. In the subtracter 5, there is calculated a difference between the sum value of the detected loads, which is sent from the adder 3, and the whole generator set load command value, which is sent from the setting device 4. Then, the difference is sent to a PID controller 6. In the PID controller 6, a fuel-valve load control command value is adjusted by a PID control such that the difference sent from the subtracter 5 is made smaller. Then, the adjusted fuel-valve load control command value is sent to a proportioner 9. Herein, the PID control means a control in which a proportional control (P control), an integral control (I control), and a derivative control (D control) are combined to one another.
In the proportioner 9, based on the number of the activated ones of the gas turbines 102a to 102m, the fuel-valve load control command value sent from the PID controller 6 is proportionally distributed to respective gas turbine control devices 10a to 10m. Then, the fuel-valve load control command values, which are proportionally distributed by the proportioner 9, are sent to the activated ones of the respective gas turbine control devices 10a to 10m. 
Based on the fuel-valve load control command values sent from the proportioner 9, the respective gas turbine control devices 10a to 10m control the fuel valves 104a to 104m disposed on the upstream sides of the gas turbines 102a to 102m so as to adjust valve opening degrees of the fuel valves 104a to 104m. To be specific, the valve opening degrees of the fuel valves 104a to 104m are respectively adjusted by the respective gas turbine control devices 10a to 10m, such that the loads of the gas turbine generators 105a to 105m, which are sent from the respective gas-turbine load detecting units 106a to 106m, become substantially the same as the fuel-valve load control command values, which are sent from the proportioner 9.
[Control of Steam Regulating Valve of Steam Turbine Generator Set]
With reference to FIG. 14, there is described the control of the steam regulating valve 203a disposed on the upstream side of the steam turbine 202a of the steam turbine generator set 201a. In FIG. 14, although the control of the steam regulating valve 203a is described, the steam regulating valves 203b to 203n are controlled in the same manner.
Firstly, an exhaust pressure on the downstream side of the steam turbine 202a, which is detected by the steam-turbine exhaust pressure detecting unit 206a, is sent to a subtracter 29a. On the other hand, set in a setting device 28a is a steam-turbine exhaust pressure set value, which is sent from the central feed command part, or a steam-turbine exhaust pressure set value, which is inputted by an operator. The steam-turbine exhaust pressure set value is sent to the subtracter 29a. In the subtracter 29a, there is calculated a difference between the detected exhaust pressure value, which is sent from the steam-turbine exhaust pressure detecting unit 206a, and the steam-turbine exhaust pressure set value, which is sent from the setting device 28a. Then, the difference is sent to a PID controller 98a. 
In the PID controller 98a, a regulating-valve control command value is adjusted by the PID control such that the difference sent from the subtracter 29a is made smaller. The adjusted regulating-valve control command value is sent to the steam regulating valve 203a. 
Due to the aforementioned control, a valve opening degree of the steam regulating valve 203a is adjusted such that the exhaust pressure value of the steam on the downstream side of the steam turbine 202a, which is detected by the steam-turbine exhaust pressure detecting unit 206a, becomes substantially the same as the steam-turbine exhaust pressure set value, which is set by the setting device 28a. 
[Control of Auxiliary Fuel Valves for Duct Burners of Gas Turbine Generator Sets]
With reference to FIG. 15, there is described the control of the auxiliary fuel valves 120a to 120m disposed on the upstream sides of the duct burners 119a to 119m of the gas turbine generator sets 101a to 101m. 
Firstly, a pressure of a steam, which is detected by the pressure detecting unit 301 on the upstream side of the steam turbine generator set, is sent to a subtracter 21. On the other hand, set in a setting device 99 is a steam-turbine inlet-side pressure set value, which is sent from the central feed command part, or a steam-turbine inlet-side pressure set value, which is inputted by an operator. The steam-turbine inlet-side pressure set value is sent to the subtracter 21. In the subtracter 21, there is calculated a difference between the detected pressure value, which is sent from the pressure detecting unit 301 on the upstream side of the steam turbine generator set, and the steam-turbine inlet-side pressure set value, which is sent from the setting device 99. Then, the difference is sent to a PID controller 22. In the PID controller 22, an auxiliary-fuel-valve control command value is adjusted by the PID control such that the difference sent from the subtracter 21 is made smaller. The adjusted auxiliary-fuel-valve control command value is sent to a proportioner 23.
In the proportioner 23, based on the number of the activated ones of the duct burners 119a to 119m, the auxiliary-fuel-valve control command value sent from the PID controller 22 is proportionally distributed to respective duct burner control devices 24a to 24m. Then, the auxiliary-fuel-valve control command values, which are proportionally distributed by the proportioner 23, are sent to the activated ones of the respective duct burner control devices 24a to 24m. 
Based on the auxiliary-fuel-valve control command values sent from the proportioner 23, the respective duct burner control devices 24a to 24m control the auxiliary fuel valves 120a to 120m disposed on the upstream sides of the duct burners 119a to 119m so as to adjust valve opening degrees of the auxiliary fuel valves 120a to 120m. To be specific, the valve opening degrees of the auxiliary fuel valves 120a to 120m are respectively adjusted by the respective duct burner control devices 24a to 24m, such that the detected pressure of the steam, which is sent from the pressure detecting unit 301 on the upstream side of the steam turbine generator set, becomes substantially the same as the steam-turbine inlet-side pressure set value, which is set by the setting device 99.
[Control of Turbine Bypass Valve on Bypass Line Connected to Gas Turbine Generator Set]
With reference to FIG. 16, there is described the control of the turbine bypass valve 123a on the bypass line 124a connected to the gas turbine generator set 101a. In FIG. 16, although the control of the turbine bypass valve 123a is described, the turbine bypass valves 123b to 123m are controlled in the same manner.
Firstly, an exhaust pressure on the downstream side of the heat recovery steam generator 111a, which is detected by the heat-recovery-steam-generator exhaust pressure detecting unit 121a, is sent to a change rate limiter 38a, a subtracter 41a, and a subtracter 44a. Set in the change rate limiter 38a is a pressure change rate, based on the structures of the respective instruments of the heat recovery steam generator 111a. The exhaust pressure sent from the heat-recovery-steam-generator exhaust pressure detecting unit 121a is adjusted by the change rate limiter 38a, such that a change rate of the exhaust pressure becomes the set pressure change rate or smaller. Then, the smoothened exhaust pressure is sent to a low value selector 40a. On the other hand, set in a setting device 39a is a maximum pressure set value, based on the structures of the respective instruments of the heat recovery steam generator 111a. The maximum pressure set value is sent to the low value selector 40a. The low value selector 40a selects a lower one of the smoothened exhaust pressure, which is sent from the change rate limiter 38a, and the maximum pressure set value, which is sent from the setting device 39a. Then, the selected control set value is sent to a subtracter 41a. 
In the subtracter 41a, there is calculated a difference between the exhaust pressure, which is sent from the heat-recovery-steam-generator exhaust pressure detecting unit 121a, and the control set value, which is sent from the low value selector 40a. Then, the difference is sent to a PID controller 42a. In the PID controller 42a, a turbine-bypass-valve control command value is adjusted by the PID control such that the difference sent from the subtracter 41a is made smaller. The adjusted turbine-bypass-valve control command value is sent to a high value selector 48a. To be specific, the turbine-bypass-valve control command value is adjusted such that the exhaust pressure of the steam on the downstream side of the heat recovery steam generator 111a, which is detected by the heat-recovery-steam-generator exhaust pressure detecting unit 121a, becomes substantially the same as the control set value, which is selected by the low value selector 40a. 
In addition, set in a setting device 43a is a pressure set value when activation of the heat recovery steam generator is stopped. The pressure set value is sent to a subtracter 44a. In the subtracter 44a, there is calculated a difference between the exhaust pressure, which is sent from the heat-recovery-steam-generator exhaust pressure detecting unit 121a, and the control set value, which is sent from the setting device 43a. Then, the difference is sent to a PID controller 45a. In the PID controller 45a, a turbine-bypass-valve control command value is adjusted by the PID control such that the difference sent from the subtracter 44a is made smaller. The adjusted turbine-bypass-valve control command value is sent to a switch 88a. To be specific, the turbine-bypass-valve control command value is adjusted such that the exhaust pressure on the downstream side of the heat recovery steam generator 111a, which is detected by the heat-recovery-steam-generator exhaust pressure detecting unit 121a, becomes substantially the same as the pressure set value, which is set by the setting device 43a. 
When a heat-recovery-steam-generator activation stop mode 47a is ON, the switch 88a is adapted to send the turbine-bypass-valve control command value, which is adjusted by the PID controller 45a, to the high value selector 48a. On the other hand, when the heat-recovery-steam-generator activation stop mode 47a is OFF, the switch 88a is adapted to block the transmission of the turbine-bypass-valve control command value from the PID controller 45a to the high value selector 48a. Herein, the heat-recovery-steam-generator activation stop mode 47a is a signal that is turned on, when the heat recovery steam generator 111a is in the course of activating or stopping, and is turned off when the heat recovery steam generator 111a is stably operated or stopped.
The high value selector 48a selects a higher one of the turbine-bypass-valve control command value, which sent from the ND controller 42a, and the turbine-bypass-valve control command value, which is sent from the PID controller 45a, and sends the selected turbine-bypass-valve control command value to the turbine bypass valve 123a so as to adjust a valve opening degree thereof.
Thus, when the heat recovery steam generator 111a is in the course of activating or stopping, the turbine bypass valve 123a is controlled and the valve opening degree thereof is adjusted such that the exhaust pressure on the downstream side of the heat recover steam generator 111a becomes substantially the same as the pressure set value set by the setting device 43a. On the other hand, when the heat recovery steam generator 111a is stably operated or stopped, the turbine bypass valve 123a is fully closed in principle.
Suppose that, during a stable operation of the heat recovery steam generator 111a, the exhaust pressure on the downstream side of the heat recovery steam generator 111a changes at a change rate larger than the set change rate set by the change rate limiter 38a, or that the exhaust pressure becomes larger than the maximum pressure set value set by the setting device 39a. In this case, the turbine bypass valve 123a is opened, so that there is performed a discharge control in which the steam on the downstream side of the heat recovery steam generator 111a is discharged.
[Control of Steam-Turbine Exhaust-Side Pressure Adjusting Valves Disposed on Condenser Sets]
With reference to FIG. 17, there is described the control of the exhaust pressure adjusting valves 503a to 503q disposed on the upstream sides of the condensers 502a to 502q of the condenser sets 501a to 501q. 
Firstly, a pressure of the steam, which is detected by the pressure detecting unit 302 on the downstream side of the steam turbine generator set, is sent to a subtracter 53. On the other hand, set in a setting device is a steam-turbine outlet-side pressure set value, which is sent from the central feed command part, or a steam-turbine outlet-side pressure set value, which is inputted by an operator. The steam-turbine outlet-side pressure set value is sent to the subtracter 53. In the subtracter 53, there is calculated a difference between the detected pressure, which is sent from the pressure detecting unit 302 on the downstream side of the steam turbine generator set, and the steam-turbine outlet-side pressure set value, which sent from the setting device 49. Then, the difference is sent to a PID controller 54. In the PID controller 54, an adjusting-valve control command value is adjusted by the PID control such that the difference sent from the subtracter 53 is made smaller. The adjusted adjusting-valve control command value is sent to a proportioner 55.
In the proportioner 55, based on the number of the activated ones of the condensers 502a to 502q, the adjusting-valve control command value sent from the PID controller 54 is proportionally distributed to the respective adjusting valves 503a to 50q. Then, the adjusting-valve control command values, which are proportionally distributed by the proportioner 55, are sent to the activated ones of the respective adjusting valves 503a to 503q. 
Based on the adjusting-valve control command values sent from the proportioner 55, valve opening degrees of the respective adjusting valves 503a to 503q are adjusted. To be specific, the valve opening degrees of the adjusting valves 503a to 503q are respectively adjusted such that the detected pressure, which is sent from the pressure detecting unit 302 on the downstream side of the steam turbine generator set, becomes substantially the same as the steam-turbine outlet-side pressure set value, which is set by the setting device 49.
The steam-turbine outlet-side pressure set value set by the setting device 49 is larger than the steam-turbine exhaust pressure set value set by the setting device 28a. Thus, when the regulating valves 203a to 203n disposed on the upstream sides of the steam turbines 201a to 201n can be controlled by the exhaust pressures of the steam turbines 202a to 202n, the adjusting valves 503a to 503q are fully closed, so that the condensers 502a to 502q are not operated and stopped. On the other hand, the regulating valves 203a to 203n cannot be controlled by the exhaust pressures of the steam turbines 202a to 202n, the adjusting valves 503a to 503q are opened so that the condensers 502a to 502q are operated, whereby there is performed a discharge control in which the steams from the steam turbines 201a to 202n are discharged.
As described above, in the generation plant shown in FIG. 1, the steam, which have been generated by the combined generator set 100 and used for generating a power, is used by the additional sets 401a to 401m. There occurs no problem, when the power generation load command for the combined generator set 100 and the load commands for the additional sets 401a to 401m are balanced, in terms of steam amounts. However, the two command values are generally set independently.
For example, in a case where the additional sets 401a to 401m are fresh water generator sets, a power generation load command is lower than a fresh-water generation load command, in terms of steam amounts, in a winter season where a power consumption is low, whereby the balance between the steam amounts is lost. In this case, it is necessary for an operator to increase a load of the duct burner 119a disposed on the heat recovery steam generator so as to increase a steam amount to be generated by the combined generator set 100, whereby the whole generation plant has a different balance point from the existing balance point.
When the load of the duct burner 119a is increased while utilizing a load control of the whole combined generator set, loads of the steam turbine 201a to 201m are increased while loads of the gas turbine 102a to 102m are decreased. As a result, an amount of steam to be generated by the gas turbines 102a to 102m is decreased.
Thus, under condition that the load control of the whole generator set is manually performed so as to stop the load control, the load of the duct burner 109a is increased to a suitable load, the turbine bypass valve 123a is opened, and thereafter the load control of the whole generator set automatically performed. When the power generation load command cannot be satisfied, the same procedure is repeated.
Since an energy input by the duct burner 119a to the heat recovery steam generator is changed so as to change a steam amount, there is a delay of the heat recovery steam generator, which makes such an operation very difficult. In order to balance the power generation load command and the steam amount used by additional sets, an operator should have a skill and it takes a lot of time for the operation.
In addition, during this operation, the load control is not performed, and thus there is a problem in that a long-term power generation load command cannot be satisfied. Further, there is a possibility that the turbine bypass valve 123a may be unnecessarily opened so that a steam is supplied to the additional sets, which impairs the efficiency of the generator sets.
In addition, in the conventional plant control device 800, there is a problem in that a load control range of the whole generator sets is ranging from (minimum load of all the gas turbines)+(a certain load of all the steam turbines at this time) to (maximum load of all the gas turbines)+(a certain load of all the steam turbines at this time), and thus an operation deviating from the range is impossible. Further, a variation of a system frequency can be amended only by the gas turbine, there is a problem with a responsibility of the whole generator sets.
Moreover, volumes of each gas turbine and each heat recovery steam generator tend to be enlarged, and thus a volume of the steam turbine tends to be enlarged in accordance therewith. Thus, there is a case wherein a load command value sent from the central feed command part is independently supplied to each generator, in addition to the whole generator sets. In this case, there is a problem in that the conventional plant control device 800 cannot cope with this case.